EQT Corp (EQT) 2014 Q4 法說會逐字稿

Good day, and welcome to the EQT Corporation year-end 2014 earnings conference call.

Today's call is being recorded.

(Operator Instructions)

At this time, I would like to turn the conference over to our Chief Investor Relations Officer, Mr. Pat Kane.

Please go ahead, sir.

Thanks, David.

Good morning, everyone, and thank you for participating in EQT Corporation's year-end 2014 conference call.

With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream and Commercial; and Steve Schlotterbeck, Executive Vice President and President, Exploration and Production.

This call will be replayed for a seven-day period beginning at approximately 1.30 PM Eastern Time today.

The telephone number for the replay is 888-445-1112 with a confirmation code of 8636267.

The call will also be replayed for seven days on our website.

To remind you, the results of EQT Midstream Partners, ticker EQM, are consolidated in EQT's results.

There was a separate press release issued by EQM this morning, and there is a separate conference call at 11.30 AM today, which requires us to take the last question at 11.20 on this call.

If you are interested in the EQM call, the dial-in number is 913-312-9034.

The confirmation code is 8851668.

In just a moment, Phil will summarize EQT's operational and financial results for the year-end 2014.

Next, Steve will summarize the capital budget revisions and the reserve report.

Finally, Dave will provide a summary of our strategic and operational matters.

Following the prepared remarks, Dave, Phil, Randy, and Steve will be available to answer your questions.

I would like to remind you that today's call may contain forward-looking statements relating to future events and expectations.

You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements listed in today's press release under risk factors in the EQT's Form 10-K for the year-end December 31, 2013 which was filed with the SEC, and is updated by any subsequent Form 10-Qs which are on file at the SEC and available on our website, and the Company's Form 10-K for year-end December 31, 2014 which is scheduled to be filed with the SEC next week.

Today's call may also contain certain non-GAAP financial measures.

Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations for the most comparable GAAP financial measure.

With that, I would like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release morning, EQT announced 2014 adjusted earnings of $3.40 per diluted share, compared to $1.97 per diluted share in 2013.

The high level story for the year as well as the fourth quarter was very strong volume growth, and overall lower unit cash costs.

Notably, production volumes were 26% higher than last year, and midstream gathering volumes were up by 27%.

As a result, adjusted EQT earnings, EPS, and operating cash flow for 2014 were all up considerably over 2013 by any measure, although both years were impacted by some unusual items that should be considered when interpreting and comparing results.

I will touch on a couple of these items in my comments.

But I do refer you to our non-GAAP reconciliations in today's release for more details.

Also, adjusted operating cash flow of $1.4 billion in 2014 was up considerably, at 19% higher than 2013.

As I mentioned, we had several unusual items impacting earnings during 2014.

In the second quarter, EQT completed an exchange of our Nora assets with the Range Resources Corporation for 73,000 net acres in the Permian basin.

We did record a $34 million gain at the time on that transaction.

In the fourth quarter of 2014, EQT recognized pretax impairment charges of $162 million on our Ohio Utica shale properties where estimated ultimate recoveries, or EURs, were significantly below our expectations; and also a $105 million impairment on our Permian Basin properties as a result of the decline in oil prices.

Also in the fourth quarter, EQT contributed $20 million to our charitable foundation.

Fourth quarter 2014 adjusted earnings were $0.96 per diluted share.

That compares to adjusted EPS of $0.39 in the fourth quarter of 2013, as significantly higher production and midstream volumes once again drove results.

Adjusted operating cash flow at EQT was $390 million in the fourth quarter, compared to $314 million for the fourth quarter of 2013.

Our operational performance continued to be outstanding in the fourth quarter, with 33% higher production volumes in the fourth quarter 2013.

We also realized 40% higher gathering volumes than last year, and continued low per unit operating costs in both businesses.

Finally, in the fourth quarter, the effective tax rate was actually negative as the full year 2014 effective tax rate of approximately 30% ended up lower than the 33% which we had applied to the first three quarters of 2014.

The lower full-year rate resulted from several factors, including some state tax planning that was implemented in the fourth quarter, the continuing impact of blending in the growing nontaxable EQM partnership earnings that are consolidated with EQT, and low pretax income as a result of the impairments in the fourth quarter.

Now moving on to a brief discussion of results by business segment.

I will limit my discussion to the full-year results, as the explanations for the full year for the most part, apply to the fourth quarter as well.

So starting with EQT production operating results.

As has been the case for many years now, the big story in 2014 at EQT production was the growth in sales of produced natural gas.

As I mentioned the growth rate was 26% higher for the year driven by sales from our Marcellus wells.

2014 was our fifth straight year of more than 25% sales volume growth.

The EQT average realized sales price was relatively flat at $4.16 per Mcfe and about $0.04 lower than it was in 2013.

For segment reporting purposes, of that $4.16 per Mcfe realized by EQT Corporation, $3.23 was allocated to EQT production, with the remaining $0.93 to EQT Midstream.

The majority of this $0.93 at midstream is for gathering which averaged $0.73 per Mcfe.

I would like to summarize a few of the changes that we made to our price reconciliation table, which should help in understanding the build-up of our realized price, which excludes non-cash impacts.

First, we applied the processing deduction directly to the liquid sales, rather than averaging those deductions across all gas and liquids volumes.

And secondly, we moved the BTU uplift to the natural gas sale section of the table, to reflect the fact that on average our gas has a higher BTU content than the NYMEX spec, primarily as a result of ethane that is sold as methane.

Because of that higher BTU value, we realized a higher price per Mcf, than NYMEX which is reflected in the table.

And then finally, we added an average differential line.

The average differentials include the impact of local basis, recoveries received from selling some of our natural gas into higher priced markets, recoveries from the resale of unused capacity, and the impact of cash settled basis swaps.

We believe these changes better explain the sales price that we receive our gas.

For the full-year, total operating expenses at EQT production were $867 million.

Excluding the impairment charges were 9% higher year-over-year.

Absolute DD&A, SG&A, LOE, and production taxes were all higher, again consistent with the significant production growth.

Moving onto the midstream business, operating income here was up 17% year over year, mainly as a result of the continued growth of gathered volumes, and the subsequent increase in gathering total operating revenues.

Transmission net revenues also increased by almost 41% year over year, as the result of an increase in firm contracted capacity.

Net operating expenses at midstream were about 17% higher year over year, and that again was consistent with growth in the midstream business.

Finally our standard liquidity update, we closed the year in a great liquidity position, with zero net short-term debt outstanding under EQT's $1.5 billion unsecured revolver, and about $959 million in cash on the balance sheet.

And that excludes cash on hand at EQM.

Based on current commodity prices, we forecast approximately $1 billion in operating cash flow for 2015 at EQT, and that is again excluding the noncontrolling interest portion of adjusted EQM EBITDA.

So we expect to fund our roughly $2 billion 2015 CapEx forecast, again excluding EQM, with that expected cash flow and current cash on hand.

With that, I'll turn the call over to Steve Schlotterbeck to discuss the reduction in our CapEx forecast, as well as today's reserve release.

Thank you, Phil.

As you read in today's press release, we are lowering our 2015 CapEx budget by $450 million or 18% in response to the current economic environment.

This consists of $425 million in EQT production, and $25 million in EQT midstream.

Of the $425 million reductions at EQT production, $400 million is related to reductions in our drilling and completions budget.

We are reducing our Permian program to 5 wells, which are required to hold our acreage, and in the Marcellus we are narrowing our focus to our highest return Marcellus development areas; and the remaining $25 million reduction is in G&G and facilities expenditures.

These cuts do not assume any service cost deflation.

While we expect to realize significant service cost reductions, we are currently in negotiations with all of our suppliers, and do not want to forecast specific savings until those negations are concluded.

Moving on to our dry gas Utica well, as you know, we spud this Green County well in November.

During the drilling of the curve, we encountered higher-than-expected reservoir pressures.

Based on the pressures observed, we needed to significantly increase our mud weight.

However, the mud system on the rig is not rated high enough for what is required to continue drilling.

Therefore, we are now bringing in a rig with a higher-rated mud system, which has caused us to be behind our original schedule.

We expect that rig to be on location toward the end of February, but despite this minor timing setback, we continue to be excited and optimistic about our dry gas Utica potential beneath our acreage.

Finally, I would like to discuss our reserve report.

This morning we announced year-end 2014 total proved reserves of 10.7 Tcfe, with the 2.4 Tcfe or 29% higher than the previous year, and represents a reserve replacement ratio of 590%.

Extensions and discoveries totaled 3.3 Tcfe, which included 939 Bcfe of proved reserves from 220 wells that were unproved in 2013, but that were drilled or completed in 2014.

This is consistent with the Company's history of continuing to expand its footprint, and develop areas that we believe to be economic, even when they do not meet the SEC's definition of proved reserves.

Another piece of the 3.3 Tcfe of extensions discoveries was 1.4 Tcfe of previously probable and possible reserves, that we plan to drill over the next five years, that were moved to proved undeveloped due to expansion of the geographic area classified as proved, longer planned laterals, and improved type curves.

Additionally, 954 Bcfe from new locations, primarily as a result of acreage additions were booked as PUD reserves.

One final comment on proved reserves, 790 Bcfe of proved undeveloped reserves were converted to proved developed in 2014, as a result of our drilling and completion programs.

Our 3P reserves, or the total of proved, probable, and possible reserves increased 6.4 Tcfe to 42.8 Tcfe, an 18% increase over the prior year.

This increase was mostly on the Marcellus, and does not include any dry Utica.

And finally, we are adjusting our guidance for DD&A rate for 2015 to reflect the finalized reserve report.

We now estimate our per unit DD&A to be $1.17 per Mcfe, or $0.05 lower than 2014.

Also as you see in our 10-K that we expect to file next week, our after-tax PV-10 was $4.8 billion, 22% higher than last year, driven by the increase in proved reserves.

This reflects a NYMEX price, calculated in accordance with SEC requirements, that was $0.70 per dekatherm higher than in 2013.

However, a decrease in regional basis of $0.71 per dekatherm led to an effective wellhead price that was $0.01 lower than last year.

I'll now turn the call over to Dave Porges for his comments.

Thank you, Steve.

Given the straightforward results for the fourth quarter, I will limit my prepared remarks to a discussion of our two announcements back on December 8; our 2015 operational forecast, and our intent to form a second Master Limited Partnership or MLP.

As you know, this is our first conference call since we made those announcements, and we thought there might be some interest in hearing us elaborate on those topics, as both pertain to our contemplated activities in 2015.

Let's cover the MLP first.

Our intent with this new vehicle is that will allow an EQT's General Partner or GP interest in EQT Midstream Partners or EQM, including the incentive distribution rights.

And, it will also own the 21 million EQM common units that are owned by EQT.

EQT will be the general partner of the new MLP.

And as a result, EQT will continue to operate both MLPs, a distinct advantage as we execute on our development plans.

Once EQM's 2014 Form 10-K is filed and the results are incorporated into the draft prospectus, we intend to file that document, the S1, with the Securities and Exchange Commission during the first quarter.

This will begin the iterative process of review by the SEC in response by us.

So we hope to be ready for an IPO by about mid year, but the timing will depend upon that review process.

We do not believe that the rapidly growing GP cash flows are being fairly valued in the EQT stock price.

As we reviewed our alternatives to rectify that situation, we concluded that we wanted a vehicle that was publicly traded; had favorable tax attributes, such as those offered by an MLP; retains effective operational control by EQT, as long as that seemed optimal; and that would allow the tax-efficient separation from EQT should we decide to affect one in the future.

To be clear, we do believe there are significant operational synergies between a midstream and upstream business during this time of rapid growth, but recognize that this period will not continue indefinitely, and we need to be quite comfortable that the chosen structure would not preclude a tax-efficient separation should that become desirable.

At the time of the announcement, we received a few off-line questions as to why we chose the MLP structure, over the structure known as Up-C.

We did give that latter structure significant consideration, but concluded that the age of a significant portion of the EQM assets precluded favorable tax treatment offered by the Up-C structure.

Also, we concluded after much in-depth discussion with tax experts, that a tax-efficient separation was every bit as feasible for a standard MLP as for an Up-C.

Moving onto our operational forecast for 2015.

You have read about the specific statistics in the December release, and revisions in today's earnings release, and heard more about this just now from Steve.

What I would like to add to the discussion is more about our thought process, especially how it relates to our financial situation and philosophy.

As Phil mentioned, we ended 2014 with $950 million in cash at the EQT level, an investment grade rating from the three major rating agencies, zero drawn on our $1.5 billion unsecured revolver, $200 million of midstream EBITDA still owned by EQT Corp, a plan to drop our northern West Virginia gathering assets to EQM in 2015, and proceeds expected from the previously discussed GP IPO.

In that context, when we announced our budget in December, we were comfortable with a CapEx estimate that was about $1.2 billion higher than our operating cash flow estimate for 2015.

Frankly, my expectation was that the GP IPO proceeds would not be touched in any event.

That money would remain in the bank account as of the end of 2015.

Since that time, the 2015 NYMEX strip for natural gas, crude oil, and NGLs has declined significantly.

Using current prices, we estimate that our operating cash flow for 2015 will be approximately $300 million less than we anticipated at the time of that release in December.

As a result, we decided to lower our activity level to more than match the decline in operating cash flow.

So if things play out as planned, we expect to end 2015 with significant cash on hand, nothing drawn on our revolver, et cetera.

In other words, with this revision, our current expectation is that we will be in a better position from a financial liquidity perspective, than we expected at the time of the December release.

In times of financial stress such as these, we think the prudent approach is to be conservative financially.

Whatever happens over the course of the rest of this year from a financial perspective, a quicker recovery or slower recovery, the presence or absence of opportunities created by overextended peers et cetera; we believe we are better off with cash on hand, a strong credit position, a strong equity position.

In my opinion, it is too early in the cycle for us to know how this will play out.

But no matter what happens, we are confident that having a strong balance sheet will create shareholder value.

At the least, it feels good to know that we already have clear line of sight for funding robust, value accretive drilling programs this year, as well as, at least, the next couple of years.

I believe that our strong balance sheet will differentiate EQT during this low price environment, as we will be able to continue to efficiently and profitably develop our acreage over a multi-year period, and emerge from this cycle stronger than when we entered it.

In summary, EQT is committed to increasing the value of our vast resource, by intelligently accelerating the monetization of our reserves, and other opportunities.

We continue to be focused on doing what we can to increase the value of your shares.

We look forward to continuing to execute on our commitment to our shareholders, and appreciate your continued support.

And with that, I would like to turn the call back over to Pat.

Thank you, David.

That concludes today's prepared portion of the call.

David, can we please now open the call for questions?

(Operator Instructions)

Philip Jungwirth, BMO.

Hey, good morning.

On the third quarter call, you guys had talked about it being the most economical to develop the core Marcellus and Upper Devonian, it's fast, its practical.

And that you had the midstream and [FT] commitments to support mid-20% growth over the next couple of years.

Obviously a lot has changed since then, but was just wondering if you could provide any update to the longer-term growth outlook, given the reduction in 2015 CapEx.

And whether you could provide a range of sensitivities such as t at $4 gas, you could grow mid-20%s, but at $3 gas I think it's more prudent to target a mid-teens growth rate?

We are all looking at each other -- ?

We haven't actually gone through all of those sensitivities.

It is fair to say that if we spend less, then the growth rates will be a little bit less.

But frankly, we would still think that they would have approach the levels we had talked about previously, if the strip remains what it is at.

I mean, at the current strip, you probably are looking -- you might be looking more like mid to high teens for the next couple of years.

But we have tried to position ourselves so we could ramp up, as Steve mentioned, pretty quickly if need be.

I mean, that is part of the benefit of having cut back more than cash flow would have dictated that we needed to.

But we haven't really run through a variety of sensitivities in this kind of volatile market, to give you a good answer to your question about what the growth rate would be at different NYMEX prices.

Over the course of the next couple of months, we probably will run through those types of sensitivities, and certainly we will share those as we do.

Okay.

I know you guys haven't provided 2016 guidance, but how would the reduced 2015 activity plan impact your ability to ramp back up?

I know you have always talked about there being a nine-month lag in spud to sale.

So for 2015, should we think about that, just taking the sequential run rate in the back half of the year, extrapolating that into 2016, or is there the potential to just ramp back up, and any increase in well spud can still impact 2016?

Phil, this is Steve.

Yes, we continue to have a fairly long lag time from TIL, or from spud to TIL.

That will continue.

So what that means is most of the changes in 2015's CapEx plan will affect 2016 production, and we have announced no impact on 2015.

We will maintain the ability to ramp up fairly quickly, if the current price environment would approve and dictate that is a prudent thing to do.

So we could change our plans fairly quickly.

But giving that the plan we just announced with the CapEx reductions, we think it is safe to say that we expect to be in the mid to high teens production growth in 2016.

And again, if things improve and we can ramp back up then, that number would go up as well.

Great.

And then last question, has anything in the last couple of months such as gas prices or planned activity levels changed your thinking on the GP valuation?

I think last quarter you tagged it $4.6 billion, and I know there is a range based on terminal growth and the discount rate.

But the publicly traded EQM LP units have actually been pretty resilient.

I wouldn't think so, but just want to make sure?

Well, the -- our inside counselor is in the room, and are staring at us with what feels like daggers.

And they have reminded us before the call, that given that we have announced our intention to file a prospectus, an S-1, that we really shouldn't be commenting on such things.

So I hope you will understand our reluctance to answer the question.

I will comment that I think other people's GP opportunities have not necessarily been impacted by this, if they are in an area that has a favorable -- relatively favorable cost structure such as the Marcellus Utica.

Great.

Thanks, guys.

Michael Hall, Heikkinen Energy Advisors.

Thank.

Congrats on a nice quarter.

I guess, a couple of questions on my end.

Some were kind of hit on already.

But you all mentioned there were no assumed cost reductions in the 2015 budget as of yet.

I guess, number one, where are you in the process of having those conversations?

Any indications around quantifying what those might look like?

And then, secondarily, to the extent they do come in and are material, how should we think about that as it relates to the capital budgets?

Should we expect you to accelerate with those excess savings, or would that -- it sounds maybe more likely accrue to the balance sheet?

Michael, we are right in the middle of that process.

I can tell you we have contacted all of our suppliers requesting a reduction, and we are starting now to get responses, and we are pretty happy with what we are seeing so far.

But again, it is in the middle of the process, and we are hesitant to really comment in detail on it, because we don't want that to compromise any of our negotiations.

But I think over the course of the next three weeks or four weeks, we should conclude the bulk of that, and have a better idea of exactly how much savings we expect to get.

And given the -- to your question about spending the money, frankly given our ample liquidity and forecast liquidity, getting extra money doesn't really affect our thought process.

I mean, we will be making decisions about the pace of development, as we look at the market more broadly, not based on having a few bucks.

We are not uncomfortable at all.

As I think we have been saying ever since we started the ML -- the drops to the MLP a couple of years ago, we are not at all uncomfortable with having extra cash on the balance sheet.

We don't think that that prudence has hurt us in the past.

There's nothing about the current market that makes us think that is not -- that is an inappropriate approach.

So we are going to stick with that.

Okay.

Helpful color.

Thanks.

And then, the resale of excess firm has helped you out in the last few quarters or several quarters.

How long do you guys project having the ability to do that, meaning like do you up that firm in 2015 time period, or is that something you will have in your back pocket if you will, through the course of 2015?

Michael, this is Randy.

Certainly, we think that the capacity portfolio that EQT holds has value, value in the long run.

And so, we would expect that to continue for an extended period of time.

But I would also point out a great deal of the benefit that we are getting is our ability to get to further downstream markets, and to pick up better pricing as a result.

So in other words, we are just as happy with the money that we get from selling our own gas into a premium market, as we would be to sell the right to move the gas -- sell that right to somebody else.

We still get the benefit.

And of course, we continue to act capacity basically every year from now, for the next couple of three years, four years.

Okay.

Yes, that is helpful.

And then, it might be something I need to wait for, but as it relates to the second MLP -- I don't know if this has been discussed in the past or not -- but is the intention, you said you will own the GP on that, and maybe I am ahead of myself, but is there an intention to have IDRs on that?

Yes.

GP as well?

(Multiple Speakers).

No, there is not going to be -- the new GP IPO, or the GP MLP will not have an IDR structure, similar to the holdco.

Compounding IDRs?

No, the IDRs from the existing MLP end up in the new MLP.

But they will have a similar structure.

All right.

That's all I had.

Thanks, guys.

Appreciate it.

Drew Venker, Morgan Stanley.

Good morning, everyone.

You had mentioned that first Utica test and encountering higher pressure.

Can you provide any color on just how much the pressure exceeded your initial expectations?

What I will tell you is we had the mud up to 18.7 pound per gallon mud, which indicates an extremely high pressure gradient, and we were several pounds per gallon below that.

Okay.

And where was that well?

That is in Green County, southwestern Pennsylvania.

Can you remind us where you are planning to drill the other tests in 2015?

The next test is planned for Wetzel County, and beyond that it will depend on the results we see from the first two.

Okay.

So is the idea to delineate primarily West Virginia this year, aside from the Green County well?

Or is there a lot of potential you will tests in this first run within Pennsylvania as well?

I think it will be strictly dependent on what we find.

We don't have a lot of direct geologic data, so these are our first tests.

So we are going to gather a lot of data, and depending on what we see, will determine where we need to go.

The first one, southwestern Pennsylvania.

Second one, northern West Virginia, and beyond that will be determined by those first two.

Can you give us a sense of when we might get results from those first few tests?

Well, I hesitate to say that, given that these are exploratory wells, and as we have already seen, unexpected things can happen.

So we expect to be back drilling the curve in the lateral on the first well in late February.

So that should take a few weeks, and then we will be fracking the well.

So that pushes it out probably another month, but with these kinds of wells it is hard to predict.

But in the early spring, we would hope to start getting some results.

And you might share that with us at that time, or maybe it depends on what you see?

Yes, I think it depends.

Okay.

All right.

Thank you.

Neal Dingmann, SunTrust.

Good morning, guys.

Nice quarter.

Say, Steve, just for you or the guys.

One, I know the production -- I guess I should say the EBITDA cash flow guidance out there, I think you were assuming some differentials that were certainly a bit higher than what you have seen last quarter.

Just wonder how you think about that?

I think as far as what you're thinking now on cash flow.

I think you had for the quarter, if I recall what, roughly around $0.40 or so differential.

Just I guess, your thoughts on two things there, one, what are you kind of thinking about differentials here for the next, I guess, for the remainder of this year?

And how does that impact that cash flow or EBITDA?

Okay, Neal, we have this in the press release under guidance.

So the differential for the year, we are projecting at between negative $0.40 and negative $0.50.

And for the first-quarter, we expect it to be positive $0.10 to $0.15.

I guess, I understand that, Pat.

But I mean, I think back in December, you looked -- on a higher differential number you had, I thought virtually the same sort of estimate for cash flow.

So I guess, what I'm getting at, is it just the difference between the difference, in the differentials, the new change in production?

Is that what that offset there?

No.

The differential is less than $0.05 better than in December, about $0.05 better.

It is the NYMEX price that mainly is impacting the cash flow.

Okay.

You just make it around that, I got you.

Okay.

And then lastly, just on takeaway, you guys continue to do an outstanding job as far as being ahead of the curve there.

I know, versus some of your peers that still lack ample takeaway in the Utica, just your size, maybe for Steve or any of the guys, when I guess, depending on the success of some of these dry gas Utica wells, is it suffice to say you have ample takeaway in the region as those come on as well?

I think it is a little early to really try and project really what is going to happen with dry Utica, given that we haven't even finished our first well.

So I think we're going to hold off even commenting on that, until we have got some test results, and can really quantify what we think the impact of a success in the dry Utica might be.

Okay, understood.

Okay.

Thanks, Steve.

Thank you all.

Joe Allman, JPMorgan.

Thank you, operator.

Good morning, everybody.

So I know that this morning you lowered your planned CapEx budget for 2015, but I just want to compare the new CapEx budget to what you spent in 2014.

So if we were talking about just exploration and development, is your new CapEx budget for 2015 higher than what you spent for E&D in 2014, or is it flat or lower?

What does that mean for where your rig count goes from here?

Joe, it is up a little bit.

I don't actually have the number right in front of me, so we are checking on that to tell you how much.

But it is an increase over 2014.

Yes, 2014 for development, we were at $1.7 billion.

And $1.85 billion this year.

And $1.85 billion this year so.

(Multiple Speakers).

Okay, and so from here does that mean an increase in rig count or?

Well, the rig count, for the bulk of the year, we expect to have eight big rigs running, and four [topel] rigs.

So total rig count of 12.

I think we are currently at 15 as we stand today, but that will be ramping down here shortly.

Got you.

Okay, that's helpful.

And then, the reduction in CapEx, at least on the production side -- I think the old budget was $2.3 billion, and now you are at $1.85 billion, so that's a 20% decline in CapEx.

Your well count is down by 33% in the Marcellus and the Permian from what you planned in December.

So could you just help me understand the -- why the CapEx drop is not proportionate with the well drop?

Yes, there is a lot of CapEx that is for completing wells that were spud last year.

Okay.

So you have a carry -- you have the CapEx that goes against wells spud last year.

And then wells that are spud this year, there will be CapEx associated with those that carry into next year as well.

So it is very normal to have a disconnect there.

Remember, a majority -- the clear majority of what we spend on any well is spent after we've -- after the drilling rig itself has moved off the location, and yet our count is typically for spuds.

Right.

But what is the inventory of wells that you drilled that you haven't yet completed as of December 31, 2014?

There is a table in the release, we will get that in the second.

So we had 722 wells spud, and 531 of those were online at the end of the year, and there were 23 that were complete but not online.

Okay, great.

That's very helpful.

Thank you.

Stephen Richardson, Deutsche Bank.

Good morning.

David, I was wondering if you could at risk of raising the ire of your general counsel, I was wondering if you could talk about your comments about the tax-efficient separation potential of this new holdco?

And are there any restrictions on, or are there any requirements on EQT C-corp's ownership of this structure going forward?

Yes, there will be with any of these things.

It is not specific to our situation.

But the requirements have more to do with how much -- indirectly I guess you would say, how much of the ownership of the underlying operating assets that we have.

So that's -- it wouldn't be specifically EQT's ownership of this GP holdco, it would be more related to that ownership times the holdco's ownership of EQM.

That would really be more of what would be looked through.

So exactly how any such entity goes about optimizing that is, it kind of depends on the circumstances, and we would be taking look at that.

But that is really issue.

It is not the standard C-corp/C-corp, where you think about, you need to have 80% ownership, and spend 80%, if that's what you're getting at.

It's a much lower threshold, but your requirements are tied to what that underlying -- the ownership of the underlying operating business is.

Got it.

Okay.

And is there any, as you think forward, acknowledging the synergies between these two businesses in the next couple of years certainly, as you think forward to certainly building potentially the MVP pipeline, are there -- do think there is a relationship between when the timing of this potential tax efficient separation would come, and the funding needs of EQM building new projects?

Are those two issues related, or are they independent?

How do we think about that in terms of timing?

I haven't really thought that EQM's funding needs are necessarily related to that.

Though I would grant you, that given what we just talked about -- when you need more funding that you can get to the point where you dilute the parent company's ownership sufficiently, that you would say, geez, you better make a more before you pass through that threshold.

So certainly that would -- that could factor into it.

But there is a variety of ways that one could deal with it in the meantime.

More broadly, but really just looking at what is the best way to create shareholder value for EQT shareholders.

That is the governing issue.

But the comment that you're making about EQM's ultimate growth is certainly a fair one, as that does impact the -- that is one of the factors that one would look at.

Got it.

Okay.

Thank you.

If I could follow-up just with a quick one for Steve.

The decision to cut back on the Marcellus, can you talk a little bit about where you're going to be focusing activity?

I would assume that this would be the less [C] country drilling certainly, and more Green and Wetzel drilling in terms of the core program for 2016.

How do you balance that, with what is going on with your processing margin, and some of the issues right now in the NGL market in the Southwest?

If you could just talk to that a little bit, it would be useful.

Yes, well, I think you actually answered your own question.

So our focus is definitely going to be in our core southwestern Pennsylvania, northern West Virginia areas.

Until recently, our northern West Virginia development had a slightly higher return than our southwestern PA, even though the Pennsylvania wells were a bit more productive because of the liquid uplift.

The current liquids market, that's flip-flopped a little bit, so the southwestern PA dry gas area is back on top, with northern West Virginia a close second.

But pretty much pulling back everywhere else.

So, yes, the C counties, no drilling, and some of the step-out wells we were doing, especially some of the dry areas of West Virginia is where we are cutting back.

Great.

Thank you very much.

You bet.

Cameron Horowitz, US Capital Advisors.

Hey, guys, good morning.

Just a real quick question for me.

Does your production guidance bake in any expectation for production shut-ins in the shorter period, just due to pricing at all?

No.

We're not expecting any shut-in.s

Okay.

Just wanted to clarify.

Thank you.

Michael Hall, Heikkinen Energy Advisors.

Thanks for the follow up.

I was just curious as it relates to the 2015 plan, and wells put on production, any guidance around how much wells you would expect to put on production in 2015, average lateral length?

And if there is any nuance to the timing of those wells coming on, given the trajectory coming out of 2014?

Michael, I don't have the specific numbers in front of me.

But regarding the timing, I think you are likely to see production in the second and third quarters to sort of moderate a bit.

So this year will be -- first and fourth quarters will be where are growth has been.

If you look back over history, you'll see that moves around.

But we generally have a couple quarters every year with bigger sequential growth than the other two quarters.

This year is more likely to be first quarter and fourth quarter, bigger increases, just based on the timing of our drilling plan.

Yes.

Okay.

That makes sense seasonally.

Cool.

That's all I had.

Thank you.

Michael Rowe, Tudor Pickering, Holt & Company.

Hi, good morning, and thanks for taking my question.

I was just wondering if you could maybe just expand a little bit on your comments earlier, regarding the current liquids market fundamentals, in West Virginia, and just how those have deteriorated a little bit since -- even just a month or two ago.

Just wanted to see if you could expand on that maybe a little bit, and then provide any insights into your NGL realizations for 2015?

Thank you.

Yes, we have a slide in our presentation that shows, what used to be called the liquids uplift, and now we call it the liquids impact.

(Laughter).

Because essentially, the price that you get -- you still get a higher price per BTU for the liquids, but we take out the processing fee.

You end up back at even with the gas price.

So right now, they are being priced on par, net of fees.

We are not experiencing anything in a different than others.

We just -- we have less wet gas obviously that the some of our peers.

So we don't -- the impact is more muted for us, so there is probably better folks for you to ask about that question.

But so, we don't have anything really to offer, other than what you see in the market, which is that ethane prices are very weak, especially -- I mean, netted back to the wellhead especially.

And propane, because of the storage situation is also quite weak.

And there is a variety of takeaway projects that are -- they are in the market, that are designed to mitigate some of that.

But it is -- when oil prices have dropped as much as they have, it is really swimming upstream.

Okay.

That makes sense.

I guess, just a last question is, it looked like -- I felt like at your new February analyst presentation, the EQT midstream gathering CapEx has come down probably, 30%, 35%, 40% from your prior guidance.

And so, is that just related to fewer wells being drilled, and potentially fewer wells being brought online?

No, it only came down, by $25 million on a -- $250 million budget.

So it's about 10% reduction.

And that just ties to gathering systems that were being built where the drilling that has been cut, that we won't need it as soon.

It refers to what Steve had talked about in the C counties, such like that.

Okay.

Thank you.

We have no further questions in queue at this time.

I would like to turn the conference back over to Mr. Pat Kane.

All right.

Thank you, David, and thank you all for participating.

That does conclude today's conference.

We thank you for your participation.